Hydraulic fracturing is one of the petroleum (oil and gas) industry's most complex operations. Applied in an effort to increase the well productivity, in a typical procedure fluids containing propping agents are pressurized and pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending hundreds of meters out from the sides of the borehole.
Several problems have become associated with such processes, especially with regard to the placement of propping agents in fractures. For example, underdisplacement can occur if the fracture is not completely filled with propping agent in the near wellbore region, greatly reducing productivity due to the closure stresses at the mouth of the fracture near the wellbore. Such problems have been shown to cause the fracture to close upon incomplete fracture fill-up due to the high stress level in the near wellbore region, thereby reducing the effectiveness of the treatment. Similarly, overdisplacement can occur if too large a volume of propping agent is used, causing proppant to settle in the wellbore itself and cover well perforation, thereby potentially limiting and reducing well productivity.
Perhaps the most common problem associated with hydraulic fracturing, however, is that of proppant flowback following the fracturing treatment. In the treatment of subterranean wells and other formations, it is common to place particulate materials, or proppants, into the formation as a filter medium and/or as a propping agent in the near wellbore area and in the fractures extending outwardly from the wellbore. In fracturing operations, proppant is carried out into the fracture when hydraulic pressure is applied to the subterranean rock formation at a level such that cracks, or fractures, develop. Proppant suspended in a viscous fracturing fluid is carried outwardly away from the wellbore within the fractures as they are created and extended with continued pumping. Upon release of the pumping pressure, the proppant materials remain in the fractures holding the separated rock faces in an open position, thereby forming an open channel for the flow of formation fluids back to the wellbore. However, when the proppants themselves are transported back into the wellbore with the production fluids following fracturing, flowback problems arise.
Proppant flowback following hydraulic fracturing treatments has generated numerous concerns within the oil and gas industry. Following a fracture treatment, proppant flowback during cleanup, and over the lifetime of a well, can have many detrimental effects on the success of the treatment, and ultimately on the well itself. The effects include near wellbore collapse or closure, wells sanding or closing up, and damage to both surface equipment and production facilities by abrasion due to the proppant. Further problems can include the need for the separation of solids from the produced fluids, and occasional decreases in the efficiency of the fractured operation since the proppant does not remain within the fracture and may therefore limit the size of the created channel. These problems can in turn lead to reduced or ceased production from a well, increased well production costs, and numerous safety concerns.
In response to the many problems associated with proppant flowback, there have been many techniques and methods described in the art to prevent or control the flowback phenomenon. These include, for example, numerous modified proppants and proppant additives, modified treatment and flowback procedures, installation of screens, modifications to the fracturing fluid components such as cross-linkers, breakers, and buffers, and a variety of other remedial treatments. Several of these approaches are described in the following paragraphs.
For example, U.S. Pat. No. 6,330,916 (issued Dec. 18, 2001) suggests a subterranean formation treatment wherein a blend of fracture proppant material and deformable particulate materials are injected into the formation. The combination of deformable proppant material with the fracture fluid proppant material can combine to cause an increase in fracture conductivity, and in doing so reduce proppant flowback.
U.S. Pat. No. 4,506,734 (issued Mar. 26, 1985) suggests compositions and methods for reducing the viscosity of a fracturing fluid introduced into a subterranean formation. The compositions are introduced into the subterranean formation and are reportedly activated by the closing of the fractures on the compositions. At this point, the viscosity reducing composition, which is a breaker such as an enzyme, oxidizer, acid, and the like, is released and acts upon the hydraulic fracturing fluid to reduce the viscosity, and simultaneously acts to reduce proppant flowback out of the fracture.
A method of preventing displacement of proppant during hydraulic well treatments has been discussed by Erbstoesser, et al. in U.S. Pat. No. 4,421,167 (issued Dec. 20, 1983). According to the specification, buoyant or neutrally buoyant ball sealers are incorporated into the trailing end portion of the fracturing fluid. These ball sealers seat on the well perforations during the final stages of the fracture, resulting in an increase in surface pumping pressure. Such an increase in pressure signals the end of the operation, and minimizes both proppant overdisplacement and proppant flowback in the wellbore.
U.S. Pat. No. 5,103,905 (issued Apr. 14, 1992) offers a method of optimizing the conductivity of a propped, fractured formation containing proppant, a polymer, a delayed breaker and a non-delayed breaker so as to minimize such problems with hydraulic fracturing as proppant flowback. The method generally describes determining after-closure polymer viscosity of the polymer in the fracture, calculating the amount of breaker necessary to reduce the after-closure viscosity of the polymer to attain a selected permeability through the fracture, determining a minimum viscosity of the fracturing fluid containing the proppant, and introducing an effective amount of delayed breaker and non-delayed breaker. The amount of breaker introduced depends upon the results of the calculations performed, and reportedly allows the proppant to be maintained in the fracture.
The addition of fibrous materials to an intimate mixture of particles for fracturing and gravel packing in order to control particulate flowback in subterranean wells has been discussed by Card, et al. in U.S. Pat. No. 5,439,055 (issued Aug. 8, 1995) and U.S. Pat. No. 6,172,011 (issued Jan. 9, 2001). These patents describe methods for fracturing subterranean formations using one or more viscous fluids and a fibrous material as a tail-in so as to stabilize the sand pack while decreasing proppant flowback and/or fines formation. The fibers are described as being natural and synthetic fibrous materials, as well as inorganic fibrous materials.
Other similar approaches have been offered for addressing proppant flowback problems and other fracture-related difficulties, most notably the use of resin-coated proppants, resin consolidation, and/or forced closure techniques. However, these methods generally suffer from having a high cost, and ineffectiveness due to the difficulty in placing such resin-coated proppants uniformly within the fracture and/or the resin coating itself negatively impacting fracture conductivity. Other problems can arise from undesirable chemical interactions between the resin coating and components of the fracturing fluid itself, such as the crosslinking systems that are commonly employed in the art.
Still further approaches to proppant flowback control, and the associated downhole complications, have been suggested in the relevant literature. For example, J. R. Murphy, et al., in SPE 19769 (“Proppant Flowback Control”) described the use of epoxy resin-coated fracture sand which reportedly forms a highly conductive, consolidated proppant bed that is resistant to flowback. The use of deformable particles as proppants to control proppant flowback has been reported by C. Stephenson, et al. in SPE paper 56593 (“Increased Resistance to Proppant Flowback by Adding Deformable Particles to Proppant Packs Tested in the Laboratory”), while the use of high-stress, deformable particles having a needle-like shape having a reportedly higher efficiency was reported in SPE 77681 (“Exceptional Proppant Flowback Control for the Most Extreme Well Environments: The Shape of Things to Come”).
While most all of the above approaches have merits, they all also have a negative impact on production and production costs, and are not always effective or applicable to a range of situations. Additionally, some flowback control additives, while capable of being successfully applied, carry severe penalties for the retained conductivity of the treated packs, due to the pore volume occupied and their inherent ability to trap migrating fines. These additives can also seriously impact cleanup and production procedures, and exert an undesirable environmental effect.
Thus, there exists a need for a fracturing fluid system for use in hydraulic fracturing which can maintain high conductivity and increase the drag forces at failure to greater than 100%, while at the same time allowing for a “viscous fingering” of the subterranean formation to occur. This fingering could allow for an increase in the overall fracture conductivity of the formation, and simultaneously reduce the pressure gradients associated with production. There is a further need for creating directional control of the fracture, such that the perforations formed in the subterranean formation can be prevented from entering unwanted areas, e.g. water zones. Additionally, there remains a high need for long-term proppant flowback control during fracturing processes.